Search
`
October 10, 2024

Posted on

Rhode Island Governor Steps up Pace of State Climate Council

Rhode Island Gov. Dan McKee asked the state’s climate council on Thursday to step up the pace of its work to meet the objectives of the Act on Climate, which he signed in April.

The Executive Climate Change Coordinating Council (EC4) will move from quarterly to monthly meetings, and McKee said during the council’s meeting that he is working to ensure that the state’s upcoming budget meets the expanding needs of the council.

The Act on Climate directs EC4 to update the state’s greenhouse gas reduction plan by the end of 2022.

To inform that work, the council will schedule a series of dedicated virtual public listening sessions and other focus group discussions with constituents, EC4 Vice Chair and State Energy Commissioner Nicholas Ucci said during the meeting.

The GHG reduction plan will be “foundational” to the development of a strategic plan for the state that is due by the end of 2025, according to Ucci. EC4 will review other states’ climate plans and connect with Rhode Island’s climate organizations to inform the initial strategic plan framework.

“The mandate for that 2025 plan is extensive,” Ucci said, adding that it’s important for the council to build a public dashboard in the near term for metrics to measure and verify success of the plan.

The dashboard, he said, is more than just a place to calculate emissions.

“We need better insight into what matters most to our people, into our economy, and to work collaboratively to determine how best to measure progress,” he said.

The council also is immediately taking up recommendations from its Advisory Board on climate justice priorities to identify how those priorities will support the strategic plan. The board worked for several months to develop the priorities for the council.

“We cannot be successful in our climate change efforts unless we more fully understand and begin to address inequities facing those in frontline communities,” Ucci said.

Among the climate justice priorities that Advisory Board Chair Sheila Dormody presented during the meeting was a call to build out a staff that can work with frontline communities as the state builds its strategic plan.

“We recognize that we, an all-white board, are not the right people to be telling the state what climate justice priorities should be,” she said.

The board also recommended, among other things, that EC4 build a definitive map of environmental justice areas in the state and define the values and principles that will guide climate justice work.

TCI-P Status

During the council meeting, McKee reiterated his support for the Transportation and Climate Initiative Program (TCI-P), saying that without a “strong commitment” to reducing transportation sector emissions, “the state will have difficulty meeting the reduction mandates that are required in the Act on Climate.”

The Transportation Emissions and Mobile Community Act (S0872A/H6310), which would have codified TCI-P, passed the Senate in June but didn’t make it through the House of Representatives before the end of the legislative session.

Newly appointed EC4 Chair Terry Gray, who is acting director of the Department of Environmental Management, said TCI-P “is still very much active and alive.”

Robust discussions about the program are ongoing with state advocates and legislators, as well as regional stakeholders, he said. TCI-P, he added, is the “only viable and complete program” to address the state’s transportation sector emissions.

“We believe that the program has been developed and built and modeled so that the costs and benefits are well balanced and that there’s a huge opportunity here to make some investments in transportation that will position Rhode Island as a leader in clean transportation,” he said.

Posted on

NYISO Reviews Mitigation Efforts, Updates Timeline

NYISO on Tuesday presented stakeholders a comprehensive buyer-side mitigation review, provided the final draft of a study on related market impacts and updated the timeline for implementing associated rule changes.

As its resource mix evolves quickly to renewables, the ISO must ensure that it provides the right market incentives and signals to the types of resources needed to keep the lights on, Michael DeSocio, NYISO director of market design, told the Installed Capacity (ICAP) Market Issues Working Group.

“The crux of the capacity accreditation proposal is that we need to step away from a protracted four-year debate on what capacity accreditation factors should be and move towards a more deterministic process based on transparent models and assumptions,” DeSocio said.

The New York State Reliability Council process for establishing the installed reserve margin database should be “the starting point for any [capacity] accreditation studies, and we think we need to be doing those studies annually because, frankly, the changes on the grid aren’t going to wait,” DeSocio said.

Transmission sensitivity assumptions in the market impacts study include over 2.5 GW on two high voltage direct current (HVDC) transmission lines into New York City. | Analysis GroupNew York’s Climate Leadership and Community Protection Act (CLCPA) requires the state to procure large amounts of renewable energy to get to zero-emission electricity by 2040, and the coming online of so much new generation is already challenging transmission and capacity market planners.

Gov. Kathy Hochul on Sept. 20 announced the state’s solicitation process had chosen the 1,250 MW high voltage direct current (HVDC) Champlain Hudson Power Express project from Quebec to New York City, as well as the 1,300 MW Clean Path New York HVDC project from upstate to the city. Both lines will be buried under the Hudson River for many miles. (See Two Transmission Projects Selected to Bring Low-carbon Power to NYC.)

The transmission sensitivity assumptions in the Analysis Group’s market impacts study include the 2.5 GW these two transmission lines provide New York City.

NYISO in August introduced the Analysis Group study that will model 10-year capacity supply and demand curves and identify the resulting market outcomes to support buyer-side mitigation (BSM) rule revisions. (See NYISO Unveils Draft BSM Study.) The company’s Paul Hibbard will take questions from stakeholders at the Oct. 5 ICAP meeting.

Not So Fast

In July, the ISO presented a proposal to exempt most new renewable installed capacity (ICAP) resources from BSM evaluation.

As proposed, resources required to satisfy the goals specified in the CLCPA will not be subject to review by the ISO under the BSM rules, or otherwise subject to an offer floor. Exempted resources include wind, solar, storage, hydroelectric technologies, geothermal, fuel cells that do not use fossil fuels, and demand response (participating as a special case resource or distributed energy resource).

Several stakeholders asked the ISO to provide adequate time to go over the needed tariff revisions, a review that prolonged a scheduled two-hour presentation to four.

NYISO is pursuing these reforms in time for the Class Year 2021 BSM evaluations and intends to address capacity accreditation in different phases, with the Phase 1 tariff changes for the new framework to be discussed through year-end 2021, and Phase 2 discussion of procedures and details expected to start around January and continue throughout 2022.

Phase 3 will focus on implementation of the capacity accreditation review, and the ISO intends to implement the updated capacity accreditation rules for the Capability Year beginning May 1, 2024. Assessment of financial risk of changes in future revenues will be incorporated into the next Demand Curve Reset process beginning in 2023.

NYISO proposes adopting the recommendation of its Market Monitoring Unit, Potomac Economics, to translate the ICAP reference price into an unforced capacity (UCAP) reference price using the derating factor of the peaking unit underlying the relevant ICAP demand curve, DeSocio said.

Several stakeholders questioned the ISO’s emphasis on providing correct capacity market signals, suggesting that the real market mover is the state and its multibillion dollar contracts for renewable energy.

One stakeholder said that while other market regions have explored mechanisms such as an integrated clean capacity plan or forward clean energy market to help send the correct market signals to align with state policy, NYISO only is offering the capacity accreditation proposal.

Energy market prices create investment signals and operational control signals that incent resource owners to make the right decisions on following dispatch, but also provide incentives on what types of attributes the resource mix should include, Desocio said, prompting the ISO to include a carbon price in the day-ahead and real-time energy market.

“A carbon price would bolster those signals to be clear about times when we are heavily emitting carbon and therefore need a solution at a particular location that will help us avoid emitting that carbon,” DeSocio said. “There is no better way to pinpoint that need other than to put it in a locational based marginal price in the energy market. There’s no more granular way to do it.”

The capacity market is designed to ensure sufficient supply for real-time grid operations to minimize the times the ISO has to rely on involuntary load curtailment, he said.

NYISO plans to submit tariff revisions of the full proposal to the Business Issues Committee and Management Committee in October.

Posted on

SEIA Issues New US Solar Generation Goal: 30 by 30

The Solar Energy Industries Association issued a new growth target for the industry to mark the first day of its 2021 annual meeting: a rapid and unprecedented growth in solar so that it generates 30% of the nation’s power by 2030, up from 4% currently.

“We know that the economics of clean energy are there … that demand will only continue to grow,” SEIA CEO Abigail Ross Hopper said in opening the general session of the two-day virtual conference. “The timing will make or break our ability to stay on the path that the scientific community tells us is necessary to avoid the worst impacts of the climate crisis.”

To reach that goal, SEIA figures that by 2030, the industry will have to build about 125 GW of new generation annually, up from the 19 GW built in 2020; and reach a total buildout of 850 GW in total generating capacity, or nearly nine times the 95 GW of total capacity in 2020.

The huge investment, much of which would be made possible by the Biden administration’s Build Back Better bill now before Congress, would add more than $120 million to the U.S. economy annually and employ more than 1 million, SEIA argues in a release timed with the conference.

The additional solar would also offset more than 700 million metric tons of CO2 annually, up from 100 million tons in 2020, Hopper said.

“There’s incredible potential for your business to thrive. Make no mistake, public policy is critical,” she said. “As we speak, Congress is debating the details of a combined infrastructure and budget package to invest in America’s future.

“Some of the policies under consideration, including long-term extension of clean energy tax credits, investments in workforce and development and training, and enhancement to our electricity infrastructure would go a long way to ensuring we stay on track to hit our 30-by-30 goal. We cannot let this moment pass.”

Before Hopper’s announcement and the panel discussion that followed, FERC Chairman Richard Glick, National Climate Adviser Gina McCarthy and U.S. Rep. Donald McEachin (D-Va.) made remarks about the importance of solar.

“Whether you work in the clean energy industry or work in the government tackling the energy issues of the day, we’re all very fortunate to be doing so during this very exciting time, as the nation transitions to the clean energy future,” Glick said, adding that demand is driving the move to renewable energy and that market rules must keep up with the transition.

“Over the last several years, the commission has issued major rule-makings focusing on ensuring that energy storage and distributed energy resources, including behind the meter storage, can participate in wholesale markets. But our work isn’t done. For instance, we are looking at both interconnection policies and market rules to determine whether action is necessary to facilitate greater participation of hybrid projects, primarily solar and storage,” he said.

McCarthy reminded listeners that the switch to clean energy is a Biden administration priority. McEachin stressed the importance of a bill he has co-sponsored, the Environmental Justice for All Act, which will require the government to consult with environmental justice communities when proposing energy legislation.

During the panel discussion that followed, panelist Kelly Speakes-Backman, principal deputy assistant secretary for energy efficiency and renewable energy at the Department of Energy, said, “President Biden has made his climate strategy really clear that the U.S. is aiming to achieve a carbon-free power grid by 2035 and a clean energy economy for all Americans with net-zero emissions not later than 2050. These are really bold targets that he has established, really the most ambitious climate strategy that the U.S. has ever seen.”

Another panel that immediately followed grappled in more detail with the problem of aligning transmission, distribution and interconnection with these clean energy goals.

“We need to move a lot faster,” said moderator Ric O’Connell, executive director of GridLab, a national nonprofit that provides technical assistance both to regulators and advocates.

“To meet our clean energy goals, we are going to need to interconnect twice what is already in the queue in the next decade,” he said of major transmission projects that have not yet been approved.

“We’ve got a similar story at the distribution level. So we probably got thousands of projects in state-regulated distribution queues around the country. And look, not all of these are 5-kW behind-the-meter residential solar systems. Many of these are 5 to 20 MW,” he added.

Eric Ciccoretti, attorney-adviser for FERC’s Office of Energy Policy and Innovation, said the commission has just begun work on new interconnection rules, and the Advance Notice of Proposed Rulemaking process of asking for comments and suggesting what might be done typically takes years, particularly if there are appeals.

He said FERC “is seeking to understand whether there are ways to improve transmission planning and interconnection planning. Given the changing resource mix, the commission is focused on the shift from resources located close to population centers … toward resources, including renewable solar and wind, that may be located far from load centers. 

“The commission is focusing on how the changing resource mix can be accommodated to ensure just and reasonable rates while maintaining grid reliability,” he said, stressing that the ANOPR is a priority.

Comments on the ANOPR are due Oct. 12, with reply comments due Nov. 15. Ciccoretti also noted that the commission is holding a technical conference on regional transmission planning, with the focus on the incorporation of long-term forecasts into future transmission, the same day reply comments are due.

Building solar projects aimed at the distribution level is also a problem, said panelist Maggie Clark, director of government affairs at North Carolina-based Pine Gate Renewables.

“You can’t readily get distribution system data in most places, and this is very different from transmission-level information that you can get on either through FERC or through utility filings.

“And that is why a lot of developers choose to go the transmission route because you can understand where it’s easier to site projects where you’re going to have a cleaner, low-cost interconnection to the grid,” she said.

Pine Gate has about 1 GW of operational assets, she said, and another 15 GW under development. The company is active in 15 states but stays away from some states because of problems tracking down reliable information about their local distribution systems.

Posted on

Senate Hearing on FERC Jurisdiction Focuses on Everything Else

The Senate Energy and Natural Resources Committee gathered all four FERC commissioners to its hearing room in D.C. on Tuesday, ostensibly to discuss the “administration of laws within FERC’s jurisdiction.”

Sen. John Barrasso (R-Wyo.) | Senate ENR CommitteeInstead, much of the two-hour hearing was taken up by Republican members of the committee questioning the two Republican members of the commission about issues outside of FERC’s jurisdiction: state decisions about their resource mixes, energy price surges in Europe and Democrats’ proposed Clean Electricity Performance Program (CEPP).

The ENR hearing was held at the same time Defense Secretary Lloyd Austin and Gen. Mark A. Milley testified before the Senate Armed Services Committee about the U.S. withdrawal from Afghanistan, which seemed to take at least some Democratic attention away from the FERC panel. At one point, it appeared there were no Democrats in the room, as ranking member John Barrasso (R-Wyo.) briefly conducted the hearing, and three Republicans spoke in a row. That meant that, as a Democrat and not the chair, Commissioner Allison Clements was sidelined for most of the hearing.

Still, the event produced some insights into both the individual thinking of the commissioners and the philosophical conflicts between them.


FERC Commissioner Allison Clements | Senate ENR CommitteeAmong the issues that do fall under FERC’s oversight is permitting of natural gas infrastructure, and Republicans had no shortage of questions about the time it takes the commission to process applications. They criticized the commission for creating uncertainty for natural gas developers because of Democrats’ insistence on assessing the downstream impacts of projects’ greenhouse gas emissions. The issue has been one of the core disputes between Democrats and Republicans on the commission for years, with Republicans maintaining that FERC has no ability to properly assess emissions, while Democrats claim the commission is ignoring court directives to do the assessments.

Sen. James Lankford (R-Okla.) asked how the commission interprets the National Environmental Policy Act (NEPA) in determining whether to conduct an environmental assessment (EA) of a project or the more detailed environmental impact statement (EIS).

FERC Chair Richard Glick said that the D.C. Circuit of Appeals “has admonished the commission on three separate occasions just with regard to our examination of greenhouse gas emissions — [that] we actually didn’t review those emissions; we didn’t review the significance of those emissions — and the court has said all three times, ‘We’re sending this case back to FERC,’ and it causes extra delay” for project developers.

FERC Commissioner James Danly | Senate ENR CommitteeLankford followed up by asking if Glick anticipated that the commission would always do EISes going forward. Glick said that is an issue the commission is considering in its review of its natural gas policy statement. “What I hope will happen” is the commission will determine a threshold amount of emissions, below which it would only do an EA, Glick said.

But Commissioner James Danly said he was “concerned that in some, perhaps, misbegotten desire to ensure that our orders are legally durable,” the commission is taking more time than necessary to conduct an EIS, when only an EA is needed. He said that the D.C. Circuit’s remanding of project approvals is because FERC has not properly explained its decisions, violating the Administrative Procedure Act. “I don’t think it’s necessary to go through the process of conducting EISes that come to the same conclusion as the EAs did. We can handle those” issues within the orders on remand themselves, he said.

FERC Chair Richard Glick | Senate ENR CommitteeLater in the hearing, Glick responded to Danly’s assertion in answering a question from Sen. John Hoeven (R-N.D.). “The problem is that the courts keep on telling us that we keep on getting it wrong. And we’re not expediting things; what we’re doing is delaying things. Because every time we’re supposed to perform an EIS or we prepare an EA, we just ignore climate change altogether. The courts say, ‘you got it wrong,’ and we have to do it all over again. That costs billions of dollars in extra time for these pipeline projects. I think certainty is more important than whether we can do it quickly and do it on the cheap.”

Danly interjected: “There is a difference between an agency failing to properly do a NEPA review, which would be in the EA or the EIS, and from an Administrative Procedure Act standpoint, to properly explain the decision that it made partially informed by that NEPA document. In almost all of the cases in which FERC was in one way or another remanded, those were not because of failures in the NEPA document; they are failures of reasoning under the Administrative Procedure Act. Basically the court is saying, ‘You did not sufficiently explain the reason why you made this choice.’ … So saying that we can fix that problem of APA violations by having different or more robust NEPA review is simply not the reality of the remands we’ve gotten back from the courts.”

Danly: CEPP Like ‘Dropping an H-bomb’ on RTO Markets

Sen. Barrasso focused his questions to Danly and fellow Republican Commissioner Mark Christie on the CEPP. The House Energy and Commerce Committee earlier this month voted to include the CEPP in the $3.5 trillion spending bill currently on the floor of the House of Representatives.


FERC Commissioner Mark Christie | Senate ENR CommitteeThe $150 billion program would require utilities to increase the amount of clean energy distributed to customers by 4% every year, providing incentives through Department of Energy grants to those that meet the targets and penalizing those that don’t. The fate of the spending bill, let alone the CEPP, is very uncertain, in part because of reluctance over its size from Sen. Joe Manchin (D-W.Va.), chair of the Senate ENR Committee.

Barrasso called it “a scheme.”

“It would use an estimated $150 billion of taxpayer dollars to pay off the largest utilities in the country to deploy Democrats’ favorite energy sources,” he said. “At the same time, it will allow those utilities to charge their customers for new transmission lines to service these facilities. To add insult to injury, Democrats do not plan to debate and consider this legislation through regular order.”

Sen. Joe Manchin (D-W.Va.) | Senate ENR CommitteeHe asked Danly if the program would lead to energy shortages and higher prices.

“I think it is almost inevitable” Danly said. “I typically don’t think it’s my role to comment on the legislation before Congress, but in this case, I want to be responsive to your question. … The text of the bill, as I read it, seems to create an incentive and penalty structure that would absolutely change and frustrate every subtle expectation we have for these slowly developed, incrementally produced markets of ours, effectively dropping an H-bomb into the middle of them. It will effectively end the markets as being anything other than administrative constructs for the purposes of balancing and dispatch.”

Danly later softened his remarks somewhat, saying that, if passed as written, the consequences of the program would be, “one way or another … profound, are going to be disruptive and at the moment they are basically incalculable. And … I don’t want to make this sound like a plea for mercy, [because] though we have no role in implementing any of what’s in that bill, FERC as a practical matter is going to be the forum in which those disputes are adjudicated.”

For his part, Manchin did not bring up the program in his opening remarks or questions, instead focusing on generic issues of reliability and affordability.

Posted on

California PUC President to Step Down

California Public Utilities Commission President Marybel Batjer said Tuesday she would step down at the end of the year with five years still left in her seven-year term.

Batjer broke the unexpected news in a letter to CPUC staff Tuesday.

“I write to inform you, after much thinking and reflection, that I have decided to conclude my service as president of the CPUC at the end of this year,” Batjer wrote. “This was a difficult decision, as I am so proud of the work we have done together in the face of a changing climate and global pandemic.

“Your deep commitment to our mission to ensure Californians have access to safe, clean and affordable utility services has sustained me during my tenure and makes it very tough to leave,” she told commission staff.

Gov. Gavin Newsom named Batjer, then the state’s government operations secretary, to fill out the term of retiring President Michael Picker in July 2019 and reappointed her to a full term last year.

In her decades of government service, Batjer had established a reputation for shaking up entrenched bureaucracies. She served as former Gov. Arnold Schwarzenegger’s cabinet secretary, and Gov. Jerry Brown named her in 2013 to head the Government Operations Agency, a new entity charged with improving efficiency and accountability in state government. Newsom kept her on in that role and put her in charge of reforming the Department of Motor Vehicles, one of the state’s most inefficient bureaucracies.

When Picker decided to retire, the governor assigned Batjer the job of speeding up the CPUC’s ponderous decision making as it struggled to cope with more wildfires, capacity shortfalls and the crimes and bankruptcy of Pacific Gas and Electric. (See Newsom Names New California PUC President.)

“She is about reorganization. She is about governance,” Newsom said at the time, calling her “one of the best in the business.”

As part of PG&E’s Chapter 11 reorganization, Batjer insisted on and obtained additional oversight of the troubled utility. The new powers included a six-step enforcement process that could eventually end with PG&E’s license being revoked. It is currently in the first step of that process for failing to clear trees from its power lines, resulting in wildfires.

The CPUC has worked to prevent more fires and to rein in the use by investor-owned utilities of public safety power shutoffs under Batjer’s leadership.

The commission also came under fire for failing to anticipate the capacity shortfalls that have plagued the state in the past two years and are expected to continue next summer. The retirement of fossil-fuel plants without sufficient replacements led to rolling blackouts in August 2020 and close calls on subsequent occasions.

The CPUC is charged with ordering procurement by the state’s three big IOUs: PG&E, Southern California Edison and San Diego Gas & Electric

“It’s difficult to understand why the CPUC did not appreciate the gravity of the shortfall sooner and take action to mitigate its impact,” Chris Holden, chairman of the state Assembly’s Utilities and Energy Committee, told Batjer at a hearing in January 2020. (See CPUC President Vows to be ‘Damn Nimble’.)

In response, the CPUC ordered load-serving entities under its jurisdiction to procure large amounts of new capacity including an additional 11.5 GW in June. (See CPUC Orders Additional 11.5 GW but No Gas.)

“Since my appointment, the CPUC has been called upon to translate its rules and processes into timely actions and outcomes to better protect and improve the quality of life for Californians,” Batjer said. “I can say with confidence that we — at all levels of the CPUC — have worked tirelessly to support Californians during these challenging times. This became my mission, and I will leave the CPUC knowing its leadership will continue to uphold this focus and determination.”

During Batjer’s tenure, CPUC commissioners became embroiled in an ugly and very public battle with former executive director, Alice Stebbins, whom they fired for allegedly hiring poorly qualified former colleagues for key positions. Stebbins has continued to criticize the commission in the media and to sue the commission, claiming she was retaliated against for blowing the whistle on $200 million in missing funds. (CPUC Fires Executive Director for Improper Hiring.)

The fight with Stebbins took an especially heavy toll on Batjer, colleagues have said.

Batjer said in her message to staff that she needed a change.

“I have had the privilege of serving four California governors and have given my all to public service for many decades,” she said. “I am now ready for a new challenge and adventure.”

CAISO CEO Elliot Mainzer, who has worked closely with Batjer and their counterparts at the California Energy Commission, said Tuesday, “I have very much appreciated working with President Batjer over the past year. She has brought tremendous leadership, vision, and focus to the CPUC, and I will miss interacting with her on a regular basis. I wish her the very best as she moves on to new challenges and hopefully gets some well-deserved rest.”

Posted on

New Orleans Seeks FERC Inquiry into Entergy Planning Practices

New Orleans regulators last week requested a FERC investigation into Entergy transmission-planning practices as criticism continues to mount that the utility is hindering transmission development to shield its footprint from competing energy suppliers.

The New Orleans City Council’s utilities committee voted during a Sept. 22 meeting to ask state and federal regulators to examine Entergy’s practices following the post-Hurricane Ida transmission failures.

The council’s resolution, approved unanimously, asks FERC to examine Entergy’s planning for any reliability violations.

“[T]he council … believes that FERC should exercise its regulatory jurisdiction to determine whether [Entergy Louisiana’s] transmission line failures resulted from any violations of applicable FERC or NERC reliability standards … including whether the lines were prudently operated and maintained,” the council wrote.

It asked FERC to determine “whether Entergy’s investment in transmission has allowed adequate access to competition and new technologies to enhance reliability and cost savings for ratepayers.”

The council also asked the Louisiana Public Service Commission to investigate Entergy Louisiana’s reliability planning. It said that, as a city government, it lacks the standing to order an investigation into the eight transmission lines that feed the city. All eight of the lines were knocked out of service by Ida.

“[T]he council pledges its support, encouragement and cooperation in any FERC/NERC effort to protect all of southeast Louisiana from ever facing such catastrophic transmission line failures,” the council said.

City Council President Helena Morena accused Entergy of using “threats and PR spins” when responding to the city’s inquiries about Entergy’s planning decisions.

The council is currently contemplating forcing a change in the city’s electric utility structure. Entergy has said it could either sell its New Orleans unit; merge it with Entergy Louisiana; create a standalone company without the Entergy brand; or allow New Orleans to set up a municipal utility. (See Facing City Council Inquiry, Entergy Says it Could Sell New Orleans Utility Arm.)

“Please stop acting like you are the victim. You are the Goliath. You are a powerful Fortune 500 company with all the resources in the world and record profits last year of $1.4 billion,” Moreno said during the meeting. “We are not the bullies, and we are not trying to run anyone out of town. We just want you to do your job for the ratepayers.”

The city council has charged its utility advisers with conducting its own investigation of Entergy New Orleans’ actions during and after the storm. That inquiry will pay special attention as to why Entergy didn’t immediately activate the blackstart-capable New Orleans Power Station. When Entergy was seeking council approval for the plant in 2018, officials promised the city council that the unit could provide blackstart services following major storms. (See Entergy Touts Restoration; NOLA Leaders Question Lack of Blackstart Service.)

The city council said its utility advisors also will file comments regarding Entergy’s grid performance after Hurricane Ida in FERC’s examination of climate change and extreme weather events’ impact on grid reliability (AD21-13).

Entergy did not respond to RTO Insider’s request for comment.

The company did, however, tout the role of its rebuilt natural gas system in storm restoration, saying it played a “quiet, yet significant role” by supplying the New Orleans Power Station and city generators used for pumping floodwaters. Entergy almost completely rebuilt its gas system after 2005’s Hurricane Katrina.

NOLA Raises Bar for Cost Recovery 

Meanwhile, New Orleans Councilmember Kristin Palmer brokered yet another unanimous resolution last week that says the council will only consider rate increases tied to recovery costs after a “careful evaluation” of the proposed increases.

“We need to be very clear here: Entergy failed the people of New Orleans,” Palmer said in a press release. “It’s inexcusable that our entire city was left in the dark for weeks following Hurricane Ida. People died. Most of them were part of our city’s most vulnerable populations who suffered in the sweltering heat. Asking for the people of New Orleans to pay more for bad service caused by obvious negligence is not going to cut it.”

The resolution dictates that any cost “caused by the failure of power utilities during Hurricane Ida cannot simply be passed onto Entergy’s customers.” It would require Entergy New Orleans to submit to an “open and transparent” review of its actions and plans to prove that the city’s power outage wasn’t a result of utility failures before the council could consider storm recovery rate increases.

“It’s not enough to just wag our finger at Entergy,” Palmer said. “We need to let them know that we aren’t going to stand for avoidable negligence that kills our people. Anyone else in New Orleans who doesn’t do their job doesn’t get paid. The same should go for Entergy.”

The council said that before Hurricane Ida’s landfall, Entergy began seeking $38.5 million from customers to address 2020 power restoration costs related to hurricanes Laura, Delta and Zeta.

“[I]n spite of these substantial investments borne by ratepayers, residents and businesses faced prolonged power outages following Hurricane Ida,” the council said.

Quashing Line Development? 

The recent scrutiny of the Louisiana Entergy system following Hurricane Ida has spurred a reexamination of some of the company’s past planning decisions and whether they were motivated by preservation of the utility’s monopoly.  

In 2016, MISO and Entergy agreed to build a $74 million 230-kV transmission line to ease the Amite South load pocket that includes New Orleans in southern Louisiana. The line would have connected two substations and boosted reliability. Four years later, Entergy canceled the project after it built the nearby $900-million, 950-MW St. Charles combined cycle gas turbine west of New Orleans.

Southern Renewable Energy Association (SREA) Executive Director Simon Mahan said the gas plant’s construction and subsequent cancellation of the line ensured that local cooperatives had no choice but to purchase energy from Entergy.

A similar scenario could be playing out with MISO’s second-ever competitively bid transmission project, the Hartburg-Sabine line in East Texas. Despite MISO awarding construction responsibilities to NextEra Energy in 2018, development of the line has ground to a standstill. (See Uncertainty Deepens for Hartburg-Sabine Project.)

In 2019, Texas passed a right-of-first-refusal law that handed the project to Entergy Texas, the incumbent transmission company. The U.S. Department of Justice opposed Texas’ ROFR law as anti-competitive, and NextEra filed a federal lawsuit. (See NextEra Appeals Court Decision on Texas ROFR Law.)

The Hartburg-Sabine line now languishes in “legal limbo,” according to the SREA, despite MISO’s projections of a 2023 completion estimate. NextEra still lists the project on its website.

Last year, Entergy Texas issued a request for proposals for a 1.2 GW natural gas plant along the line’s route. The $1 billion power plant, expected to be operational by 2025, could supplant the $115 million line.

Entergy has denied that it tries to stall transmission line approvals and said while it works in collaboration with MISO, the RTO ultimately decides on grid expansion. The grid operator has also characterized its transmission planning as a collaborative process between it and its stakeholders.

Other stakeholders have said Entergy and state regulatory consultants deliberately try to slow the RTO’s planning process by raising frequent objections and demanding more studies to back up MISO’s renewable projections. Environmental advocates recently accused Entergy and regulatory consultants of dominating conversations in long-range planning workshops. (See Tensions Boil over MISO South Attitudes on Long-range Transmission Planning.)

Posted on

Report Projects Arizona Ratepayer Costs for Going Clean

Arizona’s public utilities could use current technology to get to 80% clean electricity while maintaining reliability and cost-effectiveness, according to a consultant’s report prepared for the Arizona Corporation Commission.

But going from 80% to 100% clean energy would be more of a challenge, said the report from Ascend Analytics and Verdant Associates.

“Cost-effectively achieving higher than 80% clean energy while maintaining reliability requires innovation in clean energy technologies, such as green hydrogen, long-duration storage, advanced nuclear, or something else we haven’t thought of yet,” Ascend said in presenting its findings to the commission on Tuesday.

ACC asked for the analysis to see how much customers’ electric bills would change under the commission’s proposed energy rules.

The rules would require the state’s electric utilities to cut carbon emissions 50% by 2032 and 100% by 2070. ACC voted in May to advance the rules, which still must return to the commission for final approval. (See Arizona Regulators Revive Clean Energy Rules.)

80%, 100% Scenarios

Ascend’s analysis looked at the impact of an 80% and a 100% clean energy requirement for electric utilities by 2050, as compared with a “least-cost” case. The least-cost scenario is based on a “traditional approach” to resource acquisition, Ascend said, including natural gas turbines for capacity, a reduction in energy efficiency savings over time and the addition of low-cost renewable energy.

In comparing the 100% clean energy scenario to the least-cost case in 2050, monthly electric bills would be $22 to $24 higher for customers of Arizona Public Service (APS); $8 to $28 higher for customers of Tucson Electric Power Co. (TEP); and $33 to $35 more for customers of UNS Electric (UNSE). Those figures are in 2021 dollars.

Shorter term, the differences are less. In 2035, monthly electric bills in the 100% clean energy scenario would be $9 to $10 higher for APS customers as compared to the least-cost case; zero to $8 more for TEP customers; and $12 to $20 higher for UNSE customers.

According to Ascend, the most significant cost increases in its analysis would occur from 2040 to 2050 in the 100% clean energy scenario, as the utilities moved beyond 80% clean energy.

“This is due to the need to convert natural gas-fired power plants to burn expensive green hydrogen and add longer duration storage (eight to 100 hours) required for capacity and reliability,” Ascend said.

Ascend noted that a recent report from the National Renewable Energy Laboratory (NREL) also found increasing costs as the power system gets closer to 100% clean energy.

“Our results highlight that getting all the way to 100% renewables is really challenging in terms of costs, but because the challenge is nonlinear, getting close to 100% is much easier,” NREL Senior Energy Analyst Wesley Cole said when the report was released.

Ascend also pointed to the difficulty of making longer-term projections.

“As with any very long-range study, results in the distant future must be taken somewhat with a grain of salt,” the consultant said. “We have little information as to what technologies will be available or how exactly the power system will evolve.”

Ratepayers Weigh In

The commission met on Tuesday and Wednesday to review the Ascend report, ask questions and hear public comments.

ACC also held three virtual town hall meetings last week to hear from ratepayers on potential cost impacts of the proposed energy rules.

Many of the town hall speakers said they weren’t concerned about increased electric bills if it meant progress in fighting climate change.

Lynne Jaffe, a retired schoolteacher, said her son grew up in Arizona and loved the state. But now, because of the heat and drought, he won’t consider living there, she said.

“I don’t care if my electricity rates double,” Jaffe said. “I’ll pay for the guy next door if he doesn’t have enough. I want a livable world.”

Commissioners also weighed in at the end of Wednesday’s meeting. Commissioner Sandra Kennedy (D) compared the commission’s decision on the energy rules to the commitment that President John F. Kennedy made in 1961 to send a man to the moon by the end of the decade. The former president set his sights on the goal without knowing how it would be accomplished, she said.

“Building a clean energy economy in Arizona is our challenge, and we must be unwilling to postpone this,” Commissioner Kennedy said. “We don’t yet know exactly how we will most economically get there, but we know the worthiness of this challenge, and we know it can be done.”

But Commissioner Justin Olson (R) said he couldn’t support a proposal that increases customer rates beyond what is just and reasonable. And uncertainty about the future is another reason to reject clean energy mandates, he said.

“That’s precisely why we should not be putting mandates on our utilities for many years into the future,” Olson said. “What we should be telling our utilities is to invest in the resources that are the most cost-effective method of meeting the energy demand of their customers.”

Posted on

Modern Grid Critical to Resilience Pathway in Vermont Climate Plan

Modernizing Vermont’s power grid will be an essential part of resilience efforts included in the state’s upcoming Climate Action Plan, despite the potential cost to ratepayers.

The state will need to prioritize “upgrades that maybe should or should not fall to ratepayers but should be done anyway to support the eventual common goal of better resilience,” Erica Bornemann, Vermont Climate Council member and director of Vermont Emergency Management, said on Tuesday during a council meeting.

The council’s Rural Resilience and Adaptation Subcommittee presented initial actions to the full council that support the recommended mitigation and adaptation pathways it prepared for the climate plan over the summer. A draft of the council’s plan, which was called for in the 2020 Global Warming Solutions Act, is due in November. The council will adopt its plan on Dec. 1 and continue public engagement to refine its recommendations to the state.

Among the subcommittee’s list of action items on hardening the state’s infrastructure to climate change was a call to find federal or other non-ratepayer funding to “defray costs of utility resilience upgrades that exceed benefits to ratepayers.” Those upgrades, according to the subcommittee, could include solar-plus-storage and microgrid projects; grid capacity upgrades to enable renewable and electrification goals; and emerging non-wires technologies that address system resilience.

“Deployment of foundational technology to support smart grids” also is important for overall resilience, Bornemann said. That support could include updating interconnection standards to enable smart inverter functionality and distributed energy resource interoperability, according to the subcommittee.

The subcommittee will continue to evaluate its list of actions as the council moves to compile the recommendations it is receiving this fall into a draft plan. As part of the evaluation process, the subcommittee must weigh all actions with the council’s guiding principles for a just transition.

Data Needs

As part of its pathway to reduce fossil fuel use in rural communities, businesses and institutions, the subcommittee put forward actions to ensure the state has the data it needs to set best practices for those groups.

Better data will allow the state to expand access to critical programs, such as weatherization for homes, businesses and municipal buildings, according to Catherine Dimitruk, council member and executive director of the Northwest Regional Planning Commission.

The subcommittee said the state should collect existing data for buildings, fleets and utility usage for benchmarking and build out data sets from there. In addition, the state should work with higher education institutions to compile fossil fuel data.

Sequestration

The Agriculture and Ecosystems Subcommittee gave the council some insights Tuesday into actions to support a sequestration pathway it recommended for the plan over the summer.

“There are a number of agricultural practices that we are going to recommend as action items to maintain and increase the level of storage and sequestration in Vermont lands,” said Billy Coster, subcommittee co-chair and director of natural resources planning at the Vermont Agency of Natural Resources.

While the subcommittee hasn’t finalized its action list, it is considering, for example, the integration of trees and grazing livestock, known as silvopasture, to support sequestration. It also is considering the practice of planting rows of trees with companion crops, known as alley cropping, and forest stand improvement, which removes undesirable trees to improve resources for desirable trees.

The subcommittee also is looking at tax incentives to encourage farmers’ forest management practices toward sequestration, as well as market-based solutions that both increase sequestration and provide income streams for landowners, Coster said.

Among the solutions under consideration are compensation options for ecosystem services, which can take the form of direct payments from government agencies for conservation, for example, or conservation easements that are based on tax breaks.

Coming Up

The council will hear on Oct. 5 from its transportation, building and electric sector subcommittees on the actions they are considering for inclusion in the draft action plan this fall.

Posted on

NJ’s EV Charger Rules Face Scrutiny

New Jersey’s proposal to ramp up the use of electric trucks by stimulating the construction and installation of more medium- and heavy-duty (MHD) charging stations ran into concerns Friday over the way the rules would provide greater assistance for chargers serving the public than those for private fleets.

Two speakers at a New Jersey Board of Public Utilities (BPU) hearing said that given the urgency to cut carbon emissions and the need to rapidly jump-start the uptake of electric vehicles, especially MHD trucks, the state should more equally support all chargers, regardless of whether they serve public or private interests.

New Jersey is looking to jump-start electric truck use by creating a network of chargers geographically distributed around the state, cutting truckers’ range anxiety and addressing fairness and environmental justice concerns. The discussion touched on the sensitive issues of how much government support clean energy projects receive and the benefits that should go to private interests in the projects.

The BPU proposal envisions private developers and investors installing, owning and operating EV service equipment and marketing the sites to customers. Electric distribution companies (EDCs) would be responsible for wiring and providing the backbone infrastructure necessary.

Part of the BPU’s proposal would allow EDCs to prepare the infrastructure for a charger installation and charge ratepayers for doing so if the site is accessible to or serves the public. But the developers of chargers for private fleets would generally have to pick up that cost themselves.

Zachary Kahn, senior policy adviser for Tesla, which is close to putting a heavy-duty truck on the market, said the BPU should adjust the proposal to “support make-ready funding for all medium- and heavy-duty vehicle chargers,” regardless of whether they are in a private depot or accessible to the public.

“Private actors that are investing in medium- and heavy-duty electric trucks are already making a significant financial commitment to reducing emissions from their fleets due to the upfront costs of electrification,” he said. “These entities already have significant skin in the game and should not be punished, or not be dinged, for wanting to put their charging infrastructure in in a nonpublic location.”

He added that because heavy-duty trucks, “by their very nature,” often operate in disadvantaged and urban communities, EDC support for private fleets would still provide a public benefit because those areas suffer some of the worst emission volumes.

Zachary Fabish, an attorney for the Sierra Club, told the board that it was “problematic” to distinguish between publicly and privately accessible chargers. The benefits of electrifying the truck fleet include the improvement in the air quality to area communities, the mitigation of climate change effects and the potentially “downward pressure on rates” as the use of the grid increases, he said.

“None of those things depend on whether or not the fleet or the chargers are public or private,” he said. “From the perspective of maximizing benefits of the public and doing everything we can to electrify as quickly as we can to address not only public health crises, but the very significant climate crisis, the distinction …. just really doesn’t make a lot of sense.”

Slow EV Truck Uptake

The hearing was the last of seven forums held to solicit public input that the BPU will now fashion into a final set of rules on which to vote. With trucking emissions accounting for 40% of the state’s carbon emissions, a sizable portion of which comes from trucks, the BPU’s charger proposal is an important element of Gov. Phil Murphy’s effort to transition the state from diesel vehicles to EVs. Murphy wants the state to reach 100% clean energy by 2050, and the state’s 2019 master plan assumes that 75% of medium-duty trucks and 50% of heavy-duty trucks will be electric by 2050.

So far, however, progress has been slow. The Port of New York and New Jersey, where much of the focus in reducing truck emissions has landed in recent years, has only a dozen or so electric trucks, most of them yard tractors that move containers around inside the port. Truckers say there are few, if any, large EVs traveling the highways.

Truckers in New Jersey, like those around the nation, cite the lack of MHD charging sites as a key obstacle to greater use of electric trucks. Other barriers include the short range of existing electric trucks — only up to about 250 miles — and the high cost of the vehicles. (See Port NY-NJ Cites ‘Hurdles’ to Employing EV Trucks.)

The question of who should fund the installation of chargers, and how, was also a topic of contention at an August hearing on the MHD proposal.

Maura Caroselli, assistant deputy rate counsel, told the board that placing the burden for charger development on ratepayers would unfairly burden low-income residents, who spend a far greater share of their income on utilities. That would hit a sector that already bears the brunt of the emissions, she said.

“Ratepayers in this situation should only bear the costs of the projects where utility expertise is required,” she said. “Charging ratepayers for medium- and heavy-duty EVs through rates is the most regressive way to charge folks.”

The government could provide incentives to partner and build relationships “with companies, such as Amazon; such as Walmart; any large company that’s driving these trucks through overburdened communities every day,” she said. “We should look to collaborate and partner with them to find a solution, because they’ve got the incentive to do it. They probably have the resources to do it.”

At the same hearing, Moises Luque, CEO at transportation company Supreme Green Team, of East Brunswick, N.J. said government incentives are key for small companies such as his.

“The upfront costs of electric vehicles are very, very high,” said Luque, who said is company is transitioning to electric trucks. “For the ones that I was looking at, the cost was about $260,000 per vehicle. For a small business owner, that is a lot of money.

“Secondly, I have to think about charging my electric vehicles,” he added. At present, he added, “I have to rely on public charging stations, which currently are not fit for big commercial vehicles. They’re located in Walmarts and malls and commercial areas, but the spaces are small and not commercial vehicle-friendly.” Setting up his own charging station, he said, would cost as much as $50,000, on top of which he would have to find land on which to put it.

Mandating EV Truck Sales

The hearing Friday also underscored the sensitivity of another Murphy administration policy designed to encourage and accelerate the uptake of MHD electric trucks: a set of rules based on California’s Advanced Clean Truck (ACT) measure. The rules would require manufacturers to meet increasing sales targets for MHD electric trucks in the state after 2025, a strategy that would be achieved through a system of credits and deficits based on the manufacturer’s sales of diesel and electric trucks in the state. (See NJ Outlines Plan to Boost EV Truck Sales.)

Although the ACT and the charger infrastructure rules are unrelated — the ACT was promulgated by the New Jersey Department of Environmental Protection (DEP) — several speakers at the BPU’s hearing cited their impact if they are adopted.

Timothy Blubaugh, executive vice president with the Truck and Engine Manufacturers Association, characterized the effort to introduce electric trucks into the New Jersey market as a three-legged stool that requires support from each leg to work. Those legs are the availability of EV trucks on the market; the willingness of trucking fleets to purchase the vehicles; and sufficient infrastructure to charge or refuel them, he said.

The ACT addresses “only one leg of the stool, and therefore it will not establish the market,” he said. Significant incentives are needed to ensure that fleets see the trucks as financially viable, he said, adding that establishing the infrastructure — the second leg — will be “complicated, expensive and time-intensive.”

“The infrastructure must be installed at terminals where trucks are parked, and it will require new maintenance and operational investments by the fleet,” he said. “Since it may take 24 to 48 months from concept to having a charging station in place, a fleet must have the infrastructure in place before receiving its first exam and plan to expand it before purchasing more.”

The best way to develop the use of EVs is to initially focus on a few “beachhead” sectors, such as parcel delivery and “intra-city pickup and delivery,” in which fleets can profitably operate, he said.

Environmental groups have recently stepped up their efforts to push for the adoption of the ACT. The Natural Resources Defense Council said wrote in an op-ed for NJ Spotlight News that ACT “is one of the best tools we have to address emissions from trucks and buses.” The Sierra Club New Jersey chapter also wrote an op-ed for the site calling on Gov. Murphy to adopt the rules so that “our communities can breathe cleaner air and our state can address our most polluting sector.”

Posted on

Consumers Offers Rebates for Night EV Charging

Michigan’s largest investor-owned utility is starting a rebate program to encourage electric vehicle owners to charge their vehicles overnight at home.

Consumers Energy (NYSE:CMS) announced the “Bring Your Own Charger” program providing a $10 monthly benefit to electric customers who charge an EV at their residence between 11 p.m. and 6 a.m. using a Level 2 charger or 240-volt charging cable. The incentive — equivalent to 4,600 free miles based on 3 miles/kWh, at $0.078/kWh — will be eligible to all Consumers customers, whether they acquired a charger when they purchased the car or a charger is provided by Consumers.

The benefit will come as a credit on the customer’s monthly bill.

Consumers’ spokesperson Brian Wheeler said it wasn’t clear now how many customers might be eligible for the program, but he hoped in a few years, thousands of customers would take advantage. To date, the company has issued rebates for slightly more than 1,000 public and home charging stations, including 30 fast public chargers. Wheeler said within three years the company hoped to have 200 fast-charging locations and more than 2,000 chargers at homes and businesses.

The announcement came several days after Gov. Gretchen Whitmer (D) announced the state’s plan to create the first wireless charging infrastructure on a public road in the U.S.

The Inductive Vehicle Charging Pilot, a partnership between the Michigan Department of Transportation and the Office of Future Mobility and Electrification, will create an electrified roadway system that allows buses, shuttles and vehicles to charge while driving. Whitmer said MDOT will seek proposals to test and implement the pilot on a one-mile section of state road in Wayne, Oakland or Macomb counties.

Wheeler said Consumers’ announcement was coincidental to the governor’s announcements, as the program had been in the works for a while. The company’s announcement was made during National Drive Electric Week. State legislators currently have proposed bills to add charging stations to public rest areas before them in committees.

Encouraging EV charging in the overnight hours will put less strain on the state’s electric grid, Wheeler said, as most electric use comes during daylight.  Some residences may need to upgrade their electric service, he acknowledged.